Ultra Petroleum Corp. (NASDAQ:UPL) Q2 2018 Earnings Conference Call August 9, 2018 11:00 AM ET
Sandra Kraemer - Director of Investor Relations
Bradley Johnson - Interim Chief Executive Officer
Garland Shaw - Chief Financial Officer
Jay Stratton - Chief Operating Officer
Jacob Gomolinski - Morgan Stanley
Marshall Carver - Heikkinen Energy
Sean Sneeden - Guggenheim
David Epstein - Cowen
Vivek Pal - Seaport
Good day, everyone, and welcome to today's Ultra Petroleum Second Quarter 2018, Earnings Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions] Please note this call is being recorded.
I would now like to turn the conference over to Sandi Kraemer, Director of Investor Relations. You may begin.
Thanks, operator. Earlier this morning, we included in our news release results for the second quarter an update for 2018. In this call, we will provide additional information with our prepared remarks and reference to our updated investor presentation that was also posted earlier today on our website. I'd like to point out that many of the comments during this conference call are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and Forward-Looking Statement section of our annual and quarterly filings with the SEC. Although we believe these expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
Also this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules can be found on our website.
Thank all of you for joining us today. With me today is Brad Johnson, our Interim Chief Executive Officer; and Garland Shaw, our Chief Financial Officer; and Jay Stratton, our Chief Operating Officer.
Now I'll turn the call over to Brad.
Thanks, Sandi. Good morning, and welcome to Ultra Petroleum's second quarter Conference Call. Today we will review the quarter's financial results and focus most of our time giving you an update on our horizontal well program, our vertical program and outline our path forward.
Ultra is in the beginning stages of developing the Pinedale field with horizontal wells. Like other basins such as Permian and Eagle Ford, with successful horizontal place the effort is no small task and it requires a systematic and data driven approach to successfully execute on this objective. With the 78,000 net acres and an operating team that has drilled more than 2,100 vertical wells in Pinedale, we are uniquely positioned to lead this effort, but it will take time and patience as we optimize our learnings and delineate Pinedale's significant horizontal potential.
As we pursue this resource expansion, we remain focused on capital efficiency, disciplined growth, free cash flow generation and the pursuit of higher returns in order to drive sustainable shareholder returns. Even in the current gas price environment Ultra's vertical inventory of more than 4,000 locations gives us the foundation to generate free cash flow, while we delineate the horizontal potential in a more controlled and a particle manner going forward.
I want to quickly go through some of the highlights of the quarter that we have included on slide 4. Production in the quarter came in at the low end of our guidance range. Base production remains strong, but our wedge volume from new horizontal wells came in below our expectations. As a result, EBITDA for the second quarter was also below expectations. Cash cost beat by $0.04 driven by lower net gathering fees benefiting from increased processing revenue.
As we outlined last quarter, we embark on a ramp up of horizontal activity in Pinedale based on extremely encouraging initial results. We brought on line 11 horizontal wells in the quarter all in the Lower Lance. This effort has yielded a wealth of information about the opportunity to expand the resource potential of our Pinedale asset.
It also came with more variability than anticipated. Based on results to date, we've increased the number of intervals in the Lower Lance from four to five and further defined two specific target zones in each of those five intervals. Later on in this presentation Jay Stratton, our new Chief Operating Officer will provide more details on our results in forward plans for optimizing and enhancing the horizontal program.
The existing production from our vertical program continues to generate the revenue and cash flow to support our horizontal program. In the second quarter, our operated vertical wells posted initial average production rates of 8.8 million cubic feet equivalent per day.
Since the first of the year, we've been providing updates on our expanded effort to hedge in order to provide cash flow visibility. Much of the edging effort for 2018 is complete and we have recently been focused on opportunities to hedge in 2019 and 2020.
With our commitment to capital discipline, we are making additional adjustments to our capital plan for 2018 to prioritize cash flow generation. While we anticipated variable results and had some encouraging results from our horizontal program.
Overall the average performance of these wells in the second quarter was below expectations and with the forward strip suggesting lower gas prices into 2019 it is appropriate to ramp down the horizontal program while they incorporate our earnings.
Fortunately with our technical expertise and robust vertical program, we have the ability to shift rather quickly as conditions warn. We recently dropped one of our four rigs and plan to run three rigs for the rest of 2018, with two rigs focused on verticals and one rig drilling horizontal wells.
Our conviction remained strong regarding the potential returns from horizontal wells in the Pinedale field. However, as we take a systematic approach to this program we want our shareholders to understand that like any new or extending play, there will be variability in our horizontal well results.
The amount of data recently collected and an enhanced integrated workflow will help us in our future development and we believe ultimately drive significant long-term shareholder value.
At this time I'll turn the call over to Garland to discuss our second quarter financial results and to provide an update on our hedging program.
Thanks Brad. The company produced an average of 779 MMcfe per day or 70.9 Bcfe of total equivalent production in the second quarter, an increase of 6% compared to the second quarter of 2017.
Production volumes include 66.9 billion cubic feet of natural gas and 667,000 barrels of oil condensate. Total cost of $2.30 per Mcfe excluding stock compensation expenses were in line with the midpoint of our expense guidance. EBITA cash cost of $0.96 per Mcfe were $0.04 lower than the midpoint of our guidance.
Including our hedges are realized revenue per Mcfe for the quarter was $2.70. Before hedges our realized average gas price per Mcf was $2.11, which equates to 75% of the average first-of-month Henry Hub price for the quarter. Our average realized low price was $64.71 per barrel excluding hedges or 95% of the average WTI oil price for the second quarter.
Our resulting EBITDA for the quarter was $122 million, which was slightly below our expectations due mainly to lower production volumes associated with new horizontal wells having average performance below our budget case.
Moving to Slide 6, the company has a very solid hedge profile in place for the remainder of 2018 and continues to add to its 2019 hedge position during the second quarter to support our operating objectives. This slide includes our total volume hedge by products for the remainder of this year and for the first and second halves of 2019.
For the remainder of 2018, we have both Henry Hub and Northwest Rockies basis hedges in place, equivalent to over 80% of our expect to gas production and a net price of $2.22 per MMbtu. After applying our 1.07 btu factor, we get an average hedged gas per mcf of $2.38.
When we take our oil hedges into account, the average price through and Mcfe for these hedge volumes is $2.77. Year-to-date our hedge program has yielded $7.7 million and realized gains. We will continue to be opportunistic in adding hedges for 2019 and 2020 to improve our cash flow visibility.
On Slide 7 you will see our outstanding debt and associate maturities. As you can see our next major maturity won't occur until 2022. The 2022 unsecured bonds which carry an interest rate of 6.875% currently comprise $700 million of our debt. After the bonds come due, we have the remainder of our 975 million term loan due in 2024 and $500 million of unsecured bonds, which carry a 7.125% interest rate and are due in 2025.
Our cash flows and availability on our revolver provide ample liquidity for us to cover all interest expenses and to execute on our development plans for years to come.
Now I'd like to turn the call back over to Brad.
Thank you, Garland. On Slide 8 we have the summary timeline breaking down the transition to the wells under development which Ultra has pursued over the last few quarters. We are still in the early stages of the transition and we remain committed to taking a major and systematic approach to expanding the Pinedale field.
Our first four wells drilled from 2016 to the first quarter of this year proved the prolific nature of the rock in Pinedale and its horizontal potential. After confirming the viability of horizontal drilling in the play we set out to accelerate this development concurrent in gathering more data along the flanks of the field.
After having tremendous success early on with two wells that had 24-hour IP rates over a 15 million cubic feet equivalent per day. We were certainly disappointed in some of the more recent wells. But as I mentioned before, variability should be expected in the early phases of any play and we certainly experience more variability than expected this quarter.
But with every well we drill, we gain additional earnings. We are expanding our technical efforts by incorporating all of our data and learnings captured today. This ongoing process will offer a great deal of insight into horizontal potential in Pinedale and Ultra stands uniquely positioned to benefit from further study of the play.
Our vertical well program gives us insight into the play no other operator can match and we look forward to better understanding the horizontal potential of Pinedale and had a best unlocked to expanding resource.
If you turn now to Slide 9, you can see our updated view of the Lower Lance and how we are now subdividing this formation into intervals and zones based on what the data is showing us to date. Through the company's horizontal delineation we have now designated five intervals within the Lower Lance, Lower Lance A through E.
Inside each of these intervals, Ultra is exploring upper and lower zone which we refer to as Zone 1 and 2 respectively. In the second quarter, Ultra focused on further delineation on the Lower Lance formation drilling and completing 11 horizontal wells landing in four different zones within the Lower Lance.
Before the wells were drilling in the Lower Lance A1 90 feet below the top of the Lower Lance formation. Four wells were drilled on Lower Lance A2 250 feet below the top of the formation. Two wells were drilled in the Lower Lance C1 690 feet below the top of the formation and one well was drilled into the Lower Lance E1 1290 feet below the top of the Lower Lance formation.
On Slide 10 we have a summary of the horizontal wells the company has drilled so far. Most of our horizontal wells drilled to date have targeted to Lower Lance formation and the west wells drilled so far are in the A1 zone, 90 feet below the top of the formation. A1 zone is not immune to variability, but the average IP of the first six wells is 27.3 million cubic feet equivalent per day.
The first four wells listed in the table were all drilled east and their average IP is 37.5 cubic feet equivalent per day, including initial yields up to 25 barrels per million. For the rest of 2018 our activity will be focused in the zone and on the east flank. During the second quarter the company also drilled four wells in the Lower Lance A2, two wells in the C1, and our first well in the E1 zone.
The four wells drilled in the A2 zone which were drilled 250 feet below the top of the formation do not perform as well as we expected and serve to highlight how much variability there is as we delineate horizontal in Pinedale. The wells drilled deeper during the second quarter to the Lower Lance C1 and E1 zones continue to highlight the multiple layers of pay available on our acreage, including these deeper wells posting two of the three highest initial oil yields to date. While they have not performed as wells in the A1, we want to better our understanding of the deeper landing zones as we continue to delineate the play.
With that summary, I would now like to welcome Jay Stratton, our new COO. Jay joined our leadership team in early June and I'm very pleased to have his experience and leadership guiding our efforts to expand and optimize the value of Pinedale.
Thank you, Brad. It's an exciting time to be joining Ultra as the company to optimize the development of the horizontal play and maximize the value of our robust vertical inventory. The team at Ultra has a long reputation as operator of the industry's most efficient drill pad development program.
We have an extensive simultaneous operations experience with pad-based drilling of over 2,100 vertical wells, something the industry is challenged with in other basins. This experience has and will continue to translate into efficiencies as we optimize the horizontal program.
And please turn now to Slide 11. I will walk you through our horizontal development workflow. The extraordinary performance of early prolific wells drilled on the eastern side of the field has given us great insight into what zones and completion designs can work in Pinedale and what has been an exceptional outcome if we could repeat that performance in many later wells without developing a more rigorous analytical approach.
Delineation to poor performing deeper zones in different areas of Pinedale has identified the importance of expanding our understanding and adding tools needed to realize the full potential of the horizontal development opportunity. Along the 3-D seismic data across our entire asset, we have an extensive knowledge base and dataset from almost two decades of the development experience along with the rigs dataset from our past acquisition of a major operator's position.
We recognized the challenge and the opportunity to execute our workflow to extend our resource and maximize the value of the horizontal development. Illustrated on the Slide 11, there is workflow progressing on many parallel pads that has been developed on our existing dataset and technology.
In simple terms our objective is to increase our understanding of the productive rock with data from our existing vertical and horizontal wells. We are also filling gaps in that data with the efficient use of new technology. We are leveraging the existing 3-D seismic data on an inversion pilot to extend understanding of rock types closer away from well control.
Our technical staff is leading the build-out of an integrated geo cellular with the industry experts in parallel with the numerical modeling works led by a firm that has added value to the most respected, large independence in the unconventional space. Our Big Data acquisition works focused on providing the information on rock properties and to construct robust models. This will allow us to understand the range of performance and future well productivity.
We will then use our deeper understanding to connect well boards to the most productive rock. Ultra is in the early stages of optimizing our horizontal completion designs. Early completions were successful, but a few design changes were attempted in later wells. We are now testing designs bias towards higher intensity stimulations that are proven successful in the unconventional plays.
Cluster density, fluid type and volume, extreme limited entry perforating and propane loading are all being optimized. Performance is tracked with an extensive data acquisition and analytical program using different pressure types, pressure transient analysis and selected production login. Our production performance is closely monitored with the intention of understanding the efficiency of the wells productivity over time including the understanding of initial stimulated rock volume or SRV and using rate transient analysis to understand how that SRV changes over time.
There is no understanding we will be recycled back into our advance geo model and numerical simulation used for further refinement of our well performance predictions in all rock types found in Pinedale. Now that we completed our initial horizontal well targeting and acquired valuable data, we intended to do our most rigorous testing in this single layer to build compliments in new zones before testing further potential with the drill bit.
Ultra's taken a disciplined process and data-driven approach leveraging our existing staff with the most respected resources in oil and gas to understand the opportunities presented by horizontal drilling in Pinedale. Using this process, data from the horizontal wells drilled to date in over 2100 vertical wells drilled by the company, Ultra is well positioned to unlock the full value of the asset.
Slide 12 provides updated economics for the horizontal well program going forward in the near term. We are focused on over 28000 net acres in the immediate flank of Pinedale where we believe we can still achieve compelling returns. We are going to further refocus our development plan on the most prolific Lower Lance A1 zone while continuing to understand opportunity in other Lower Lance zones with our horizontal technical workflow.
The Mesaverde Upper Lance also offers additional upside to be unlocked. Economics of Lower Lance A1 zone is the next one. The net gas price represents Henry Hub mine's rocky spaces and the economics include the uplift we enjoy due to the high BTU content of our Pinedale gas and the oil revenue from the associated condensate production.
In particular with the increases in oil mix from horizontal wells, our team is working to understand oil properties and completion designs that will allow for more efficient recovery of both oil and gas. These results show strong expected returns even when Henry Hub mine's rocky basis results in a net gas price below $2 per MMbtu.
Turning to Slide 13, we've updated our vertical well performance chart to feature average cumulative production over the last eight years highlighting the last quarters. While we are focused on a lot of this call on updates to the horizontal program, we are also extremely focused on continuing to optimize and maximize returns from our robust vertical program.
In 2007 with an increase in activity, more vertical wells were drilled in the flank than in the quarter. That resulted in well performance below historical averages. In 2018 as we resume a high-graded vertical drilling program, average well performance has been at record levels with activity focused in the core Pinedale.
During the second quarter of 2018 we posted the highest average IPs in the last seven quarters with our operating vertical wells having an average IP of 8.8 million cubic feet equivalent per day. The opportunity to high-grade these locations demonstrate the quality of the inventory and the ability to deliver strong margins even in stressed price environments. With the ample inventory of high quality vertical locations, we will continue to execute on a solid vertical program as we expand our understanding of the horizontal opportunities.
Now I'd like to turn the call back over to Brad.
Thanks, Jay. Our capital plan continues to be driven by the following three objectives. First, the disciplined deployment of capital and pursuit on superior returns; second, the increased visibility of cash flow, because 2018 is driven by a strong base of production from our vertical wells and our hedge book; and third to continue delineation of our horizontal development.
In the near-term while we're further studying the finer program, we are scaling back to horizontal effort. For the remainder of 2018 we plan to run three operated rigs with one horizontal rig that will be focused on Lower Lance A1 on the east flank and two vertical rigs continuing to drill across our high-graded core acreage.
Full year capital guidance remains the same at $400 million. Our pivot to horizontals last quarter actually occurred in a faster pace as we have planned. From an execution standpoint, this was positive. However, we incurred cost as part of that transition that took pressure on both our vertical and horizontal well costs.
In the second quarter, vertical wells averaged $3.6 million per well and horizontal wells cost $9.6 million. As we pivot back to more verticals in a near-term focus on horizontals on the A1 zone, we expect to drive down our well cost to previous levels. For the second half of this year, we expect to average $3.1 million of verticals and $9 million for horizontals.
Based on the lower than expected performance of our horizontal wells drilled in the second quarter, we are adjusting down full year production guidance to a new range of 273 to 283 Bcfe and for the third quarter our production guidance is 710 to 750 million cubic feet equivalent per day. Expense guidance for the year remains on track and it's summarized in the lower left part of the slide.
Now on Slide 15, we provide detailed expense guidance for the third quarter and EBITDA guidance for the full year. For EBITDA cash costs, we estimate $0.99 per Mcfe for the third quarter and $0.98 per Mcfe for the full year. With our hedges in place we expect price realizations for the year to average $2.81 per Mcfe.
Using updated expense from production guidance, we now forecast 2018 EBITDA to be $509 million. In summary I would like to thank our team for their tremendous effort and execution as we moved very quickly from vertical development to a horizontal delineation program. We remain focused on taking a disciplined approach to capital allocation to drive cash flows and shareholder value.
We are in our early days of expanding our resource potential in the Pinedale field to horizontal development that are encouraged by some of our early results. We also remain focused and committed to our vertical program. We still have thousands of locations in inventory. This program is delivering solid returns even in the current gas price environment. We look forward to sharing with investors our ongoing progress as we continue to move our vertical and horizontal programs forward.
At this time we will open the line for questions.
Thank you. [Operator Instructions] Our first question comes from the line of Jacob Gomolinski of Morgan Stanley. Your line is now open.
Hey, good morning and thanks for taking the questions. Can you help us understand why CapEx for the year isn't going down as you reduced rig count by about 25%?
Yes, we are affirming our capital for the year $400 million. We came in heavy for the second quarter as a result of higher well cost both on our vertical and horizontal program. So as we ramp down activity, we do expect our capital burn to be reduced but because of the capital in the second quarter that's keeping our full year guidance right at $400 million for now.
Okay. And then maybe I missed it, but I didn't see in early sort of [indiscernible]. So what CapEx was in Q2?
We were $160 million for CapEx for 2Q.
And then maybe just on the guidance for the rest of the year, does that incorporate the sale of the Utah asset and the 2000 barrels a day of oil production and maybe if you can just give us a sense of what the EBITDA and cash flows that was associated with that asset were?
Sure. As an update for our Utah asset, we did at the end of July subsequent to quarter end, signed a PSA selling our asset in Utah for $75 million of cash. And our forecast for the remainder of part of the year we are incorporating Utah through the month of August and that plays into the volumes and the expense forecast for that asset incorporated in the overall company numbers.
Okay. So the guidance for the year or for Q3 is assuming that the asset closes at the end of August, it was the production in September?
That's already included in our guidance, yes.
Okay. And then maybe I don't know if you could just have a sense of what the EBITDA was for that asset or the cash flow?
EBITDA of trailing 12 months is about $18 million on a trailing 12-month basis.
Okay. Sorry go ahead.
Just to clarify that was for the Utah asset.
Yeah, of course, I have a few more but I'll hop back into queue for now. Thanks very much.
Thank you. Our next question comes from the line of Marshall Carver of Heikkinen Energy. Your line is now open.
Yes. On the vertical well program, what is your inventory of vertical wells that are higher than 4 Bcf? I know you showed some slides a couple of years ago that showed the number of wells at 4 Bcf and then 3.5 and so on as you went forward in future years. But do you have a feel for how many wells you have remaining that are north of 4?
So a few comments on the vertical inventory, first, we - year end '17 our reserves were based on a relatively small pad pool [ph] frankly as we were working in our development plan, a combination of vertical and horizontal wells and we had about 300 vertical wells in the pad pool, again a much smaller, deliberately smaller case and at current prices we have about 800 wells that are economic, obviously low prices today. I don't have a number for you on wells over 4 Bcf.
Okay. Thank you. That was actually - the prior question was - all my questions have been answered between me and the prior person that was asking questions. Thanks.
Yeah. And as I comment about 800 wells at current economic for current prices, of course, we've got over 4000 vertical wells in our inventory and a significant amount of those become economic as prices would invert. And so we share some of that, the economics on our vertical slide demonstrate the economic potential of vertical program in an improving gas price environment.
Thank you. Our next question comes from the line of Sean Sneeden of Guggenheim. Your line is now open.
Hi, thank you for taking the questions. Maybe just to start Brad, can you just kind of update us on your thoughts around maintenance capital, I think previously you were thinking about $270 million figures just in light of Q2 results. Is that something we should still be thinking about or how should we I guess be thinking about that going forward?
Yeah, I think that's still a valid number and I think last quarter we talked a bit about maintenance capital at that level and if the horizontal wells were delivering above expectations we would have the opportunity to maintain flat production at lower CapEx or if horizontal wells - or if we decided to maintain CapEx and have horizontal performance contributing we would have the ability to grow at that level. Certainly the second quarter results for the horizontal wells were below expectations. I think right now to think about maintenance capital basing that on the vertical program that's been low risk, significant inventory and I think that 270 to 275 is still a fair number.
Okay and the 270 is basically on a pure vertical program?
Got it, that makes sense and then is your - the $9 million target for horizontals for second half, can you just kind of share that that split - the line of sight that you have there? Obviously I think, as you kind of said Q2 was a bit choppy with some of the - testing of some of the deeper intervals, but dig - help for us to kind of get into those type of numbers for second half?
Sure as I mentioned in my remarks, we average $9.6 million for our horizontal wells this quarter. We definitely experienced cost pressure as we were ramping up that activity. And we had shared previously and I had shared it, there was an advantage for having the ability to drill horizontals and verticals off the same pad and that was certainly the case from an execution standpoint. But we have shared equipment cost on these pads and as we are adjusting down our activity a large portion of our equip costs are now being allocated to less wells, so that's creating pressure on our costs that we're posting for the second quarter. I do expect that to go down in time as we frankly right size equipment capital on our future horizontal wells.
Got it, that's helpful and then maybe lastly, I think you commented that the goal here is that generate free cash flow for the balance of the year. How should we think about what you - what the use of any kind of free cash flow generation is for - is that debt repayment is it just kind of using as substantial war chest for AMD activity or how should we think about that?
Sure, obviously we're very focused and desire to do delever. However cash right now we have not committed it to any specific use. We want to maximize liquidity. We want to continue any incremental investments to pursue the best returns available in our portfolio. So right now we have not committed those proceeds any particular use.
Okay, that's helpful. And just remind me on that point, you don't - you're currently are restricted from buying back any of the unsecured bonds under the term loan company, is that right?
This is Garland. That's right, under the term loan and the revolver restricted we have to be three times leveraged or better in order to buy back any bond or stock.
Got it, that's helpful. Thank you very much.
Thank you. Our next question comes from the line of David Epstein of Cowen. Your line is now open.
Thanks guys for taking my call. When you spoke about the maintenance CapEx of 270 million to 275 million, what production level were you thinking? You used to talk about sort of Q4 '17 were you referring to sort of your full year '18 guidance here that's part of it? And then as also part of it, what are you thinking in terms of vertical cost when you talk about a number. Yeah, I think you talk about getting back to 3.1for the second half of the year, will you ever be able to get back to the old 2.9 or does inflation and lower scale make that tough? Thank you.
Sure, regarding maintenance capital, the number would be on a flat 2017 volume which would be 280 bcf or so. The vertical low cost, yeah, as we were ramping up horizontal and drilling both horizontal and vertical wells on the same pad, we were mobilizing equipment to complete horizontal wells which required higher pressure rated equipment. And so we had oversized equipment frankly on the completions of our vertical wells, we knew that that was part of the ability we have and the objective to ramp up. So I do see us mitigating and reversing those costs. We've had a bit of inflation pressure not a lot, but some over the last quarter, steel and fuel and I think those will - those particular items we've got built into our forward look for costs. I do think as we return back to much more of a dedicated vertical effort on one pad and horizontal on another that we will be able to revert back to those historical costs and for now we are forecasting 3.1, but my expectation is that we would get below 3 as we move forward, but for now we're going to use 3.1 for the balance of the year.
Great and obviously you are redirecting towards verticals a little bit, would - doing horizontals in the core, what are your current thoughts on that?
We believe there is potential in the core, but some of the wells we drilled this past quarter and they're - I might reference slide 10 in our in our presentation where we have the data tabulated. Ample wells we should drill four wells to the west and a few of those were testing the core up in the A1 zone and those results were not that encouraging. We saw a less yield of course as we went back to the core and we saw higher water production. There will always be some depletion risk potential as well as we drill back. So we're not going to rule that out by any means and certainly haven't condemned any zone in our entire horizontal program, but just looking at the real results on slide 10 and seeing a variability, but also seeing strong results in the A1 that's what we're going to focus near term of the drill bit, drilling the A1 to the east.
And so and in the core it's shows you have a nice a vertical column, but it's had rigidity [ph] for lack of a better word horizontally and not a high netted growth or is it something else?
Well not so much a geologic contributor, at least in the first few wells we drilled, we encountered higher water and so we may have targeted zones in the core that were - had a higher water saturation. We certainly experienced higher water on those wells and the overall deliverability was lower. So, as we drill on the core and some of those really nice sands that we've developed our vertical wells, the balancing act there is drilling good rock, but also potentially encountering some level of depletion. So that's just part of the effort that is incorporated and Jay had a lot of comments about with respect to really as to advancing in refining our models as we move forward with the horizontal effort.
Thank you very much.
Thank you. Our next question comes from the line of Vivek Pal with Seaport. Your line is now open.
Yeah, good afternoon guys. Most of my questions have been answered. Just a quick one for Garland, in the second half of this - in '18, do you expect to be cash flow neutral to modestly positive based on what I hear in terms of a declining CapEx for the second half?
So with the asset sale we actually expect to be cash flow positive in the second half of this year.
So it will be 75 million plus or it will be or you will be burning a little cash operationally.
I don't think we'll be over 75 million.
Okay and I know you just mentioned it, but I just want to be clear so normalized vertical well costs are about roughly a third of what your horizontal costs are, right in terms of CapEx?
And in vertical is it fair to assume that you can average about 8MMfe per day, is that a fair number for vertical because you've done so many?
So that was the 8.8 million cubic feet equivalent per day was the average of our operated wells in the second quarter and we anticipate drilling similar quality wells for the rest of 2018.
Okay, alright, thank you very much.
Sure, thank you.
Thank you. Our next question comes from the line of Jacob Gomolinski of Morgan Stanley. Your line is now open.
Hey thanks for taking the follow up, I just wanted to see if you had a sense of where current PDP value was or PD10 value as of today given some of the walls you drilled over the year as well as some of the production over the year so far and maybe also what the current corporate decline rate is?
Sure, so on a PDP valuation standpoint we've added wells, so our PDP base has grown through the year and from a valuation standpoint in reserve space that value is going to be much more driven by 12 month pricing used in reserve calculations. I think our PDP value is holding steady as we look at our numbers through the year. Let's see the second question. I'm sorry, second part of your question was [indiscernible].
So from a nominal requirement on our base production first year is about 25% on PDP and of course due to the hyperbolic nature of the decline curves of our wells that that in requiring [indiscernible] diminishes each year. So by year five or six you're n single digit percent declines. In Pinedale new wells and ultimately the production ends up in around 6% or 7% internal decline.
Got it and then just - that's very helpful actually, thank you very much. On the - it looks like you paid down about 2.5 million of the term loan. I think I know the answer just want to confirm as I just the MR starting up and is that just how to expect it going forward and how that will may I guess the largest impact of borrowing base, really just we're not talking huge numbers here, but just want to make sure we're thinking about it the right way?
It's a current, there's a payment due in the next twelve months, so it's carried the different spot.
Yeah, two or three across the balance sheet, we didn't actually pay it down yet. I don't know whether that starts until June 2019.
Got it, okay. That was it for me, thank you very much.
Thank you. [Operator Instructions] And I'm showing no further questions at the time. I'd like to hand the call back over to Brad Johnson for any closing remarks.
Okay, this concludes our second quarter conference call. I wish to thank everybody for joining us this morning. If you have any questions please follow up with Sandi Kraemer. Thank you and goodbye.
Ladies and gentlemen, thank you for participating in today's conference. That does conclude today's program .You may all disconnect. Everyone have a great day.